It is common practice in the oil and gas industry to cement casing string within a wellbore after drilling the wellbore to depth by introducing cement into an annular space between the wellbore and the casing string. Cementing is often completed for various reasons including restricting fluid movement between formations and to bond and support the casing string within the wellbore. Cementing can be completed in stages, with staging tools fixed in the wellbore between cementing stages.
Cementing is typically performed by circulating cement slurry through an internal bore of the casing string from the surface to the bottom of the casing string and into the annulus through a casing string shoe located at the bottom of the casing string. Often, casing strings can also incorporate float shoes or float collars to prevent backflow of the cement slurry during cementing.
To ensure proper bonding between the casing string and walls of the wellbore, the casing string is centralized within the wellbore. Concentricity provides an annulus between the casing string and the wellbore. In ideal circumstances, the wellbore and the casing string would be substantially concentric so as to provide cement about the casing string having a uniform thickness.
In vertical wellbores, centralizers are spaced periodically along the casing string to sufficiently space the casing string away from the wellbore walls. The centralizers provide sufficient annular space between the casing string and the wellbore walls for the cement slurry during cementing operations.
In horizontal wellbores, or wellbores having a lateral section, the force of gravity acting on the casing string causes the casing string to rest or lay on the bottom surface of the wellbore wall reducing the effectiveness of centralizers. Thus, during cementing operations, the cement slurry, taking the path of least resistance will tend to travel along a top of the casing string, and often resulting in the cement slurry not being placed underneath the casing string. As a result, there are a plurality of locations along a horizontal or lateral section of a wellbore where bonding does not occur between the casing string and bottom surface of the wellbore. Lack of bonding along the casing string can result in surface gas migration that has become a multi-million dollar liability per year in the industry.
While centralizers can be deployed along the casing string for use in the lateral sections or along horizontal wellbores to space the casing string from the bottom wall of the wellbore, they are not particularly effective and a smaller annulus results thereunder. Any impetus for cement slurry to flow underneath the casing string is compromised. Thus, there may not be a placement of a sufficient amount of cement thereunder for bonding between the casing string and the bottom wall of a wellbore.
As set forth in U.S. Pat. No. 5,309,996 to Sutton, it is known to reciprocate an entire casing string during the placing of cement to prevent the loss of hydrostatic pressure in the cement slurry during the cement transition period from a true fluid to a gel sufficient to prevent gas migration therethrough. However, the casing string is limited in its manipulation by a hydraulic power unit at surface with a stroke of between 2 to 60 inches and preferably 8 to 10 inches. In order to prevent surging in the cement slurry as the casing is reciprocated, a slip joint is pre-charged with a compressible gas is connected to the bottom of the casing which is maintained in contact with the bottom of the wellbore. An alternate slip joint contains an insulated liquid nitrogen container to charge the slip joint with vaporized gas.
It is also known to rotate casing strings to aid in distribution of cement along and about the casing string, however, the massive weight of the casing string tends to impede cement distribution. Further, in staged cementing, once secured in the wellbore, movement of the casing string is impeded. Casing swivels are known for de-coupling the upper portion of the casing string from the lower portions and are limited to rotation during displacement and cementing operations.
Applicant has a co-pending application for a positive cement placement tool, filed as PCT/CA2015/050236, published as WO015/143564 on Oct. 1, 2015, designating the US, and claiming priority of U.S. 61/971,345 filed Mar. 27, 2014, the subject matter of which is fully incorporated by reference herein. Applicant's positive cement placement tool utilizes a reciprocating action of the conveyance string to rotationally actuate a particular form of bladed centralizer to provide positive impetus to urge cement slurry about the conveyance string. Applicant's tool disclosed therein teaches driving rotation of the placement tool in a first direction during an upstroke of the conveyance string, and the rotation of the tool in an opposite direction during a downstroke of the conveyance string. The oscillating movement or bi-directional rotation of the tool provides positive or additional impetus for urging cement slurry about the conveyance string.
Applicant's positive cement placement tool utilizes reciprocation of the conveyance string, however, where a staging tool or other device for securing the casing string in the wellbore, such as a downhole packer, is set and cannot be moved, or where the staging tool is already cemented into the downhole portion of the wellbore, the operation of such a tool is impeded or discouraged.
In another downhole operation, in multistage fracturing operations, a string of downhole tools are spaced along a completion or casing string and are run in hole to be fixed in the wellbore, by cementing or actuation of spaced packers to isolate zones of interest. As described above for cementing, further manipulation of the conveyance string is limited once a lower portion is secured in the wellbore.
In either of the two examples of conveyance strings above, having a portion of the string secured to the wellbore limits subsequent movement of remainder of the string and impedes subsequent operations and ultimately compromises integrity of the completion.
There are as yet unsolved challenges to manipulating a conveyance string uphole of secured downhole portions of the string, particularly in the greater depth and adverse gravity effects of horizontal wellbore environments.